1. Field of the Invention
The invention relates generally to drilling muds, loss circulation materials, industrial materials, and processes to recover the industrial materials for reuse in drilling mud systems.
2. Background Art
When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, fluid used for implacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
Drilling fluids or muds typically include a base fluid (water, diesel or mineral oil, or a synthetic compound), weighting agents (most frequently barium sulfate or barite is used), bentonite clay to help remove cuttings from the well and to form a filter cake on the walls of the hole, lignosulfonates and lignites to keep the mud in a fluid state, and various additives that serve specific functions, such as polymers, corrosion inhibitors, emulsifiers, and lubricants.
During drilling, the mud is injected through the center of the drill string to the bit and exits in the annulus between the drill string and the wellbore, fulfilling, in this manner, the cooling and lubrication of the bit, casing of the well, and transporting the drill cuttings to the surface. At the surface, the mud can be separated from the drill cuttings for reuse, and the drill cuttings can be disposed of in an environmentally accepted manner.
Recycling drilled solids into the wellbore is undesirable, as this can result in smaller sizes of drilled solids which can accumulate in the drilling fluid. If the solids content increases, additional drilling fluid (water, oil, etc.) must be added to maintain the mud at its desired weight. The drilling mud and drill cuttings returned to the surface are often separated to maintain drilling mud weight, thus avoiding costly dilution. The separated solids are then discarded or disposed of in an environmentally accepted manner.
Drill cuttings can originate from different geological strata, including clay, rock, limestone, sand, shale, underground salt mines, brine, water tables, and other formations encountered while drilling oil and gas wells. Cuttings originating from these varied formations can range in size from less than two microns to several hundred microns. Drill cuttings are commonly classified according to size: smaller than 2 microns are classified as clay; from 2 to 74 microns, silt; 74 to 500 microns, sand; and larger than 500 microns, cuttings. Several types of separation equipment have been developed to efficiently separate the varied sizes of the weighting materials and drill cuttings from the drilling fluid, including shakers (shale, rig, screen), screen separators, centrifuges, hydrocyclones, desilters, desanders, mud cleaners, mud conditioners, dryers, filtration units, settling beds, sand traps, and the like. Centrifuges and like equipment can speed up the separation process by taking advantage of both size and density differences in the mixture being separated.
A typical process used for the separation of drill cuttings and other solids from drilling fluid is shown in FIG. 1, illustrating a stage-wise separation according to the size classifications. Drilling mud 2 returned from the well (not shown) and containing drill cuttings and other additives can be separated in a shale shaker 4, resulting in large particles 5, such as drill cuttings (greater than 500 microns for example), and effluent 6. The drilling fluid and remaining particles in effluent 6 can then be passed through a degasser 8; a desander 10, removing sand 15; a desilter 12, removing silt 16; and a centrifuge 14, removing even smaller particles 17, such as clay. The solids 15, 16, 17 separated, including any weighting materials separated, are then discarded and the clean drilling fluid 18 can be recycled to the mud mixing system (not shown). Agitated tanks (not numbered) can be used between separation stages as holding/supply tanks.
The recovered, clean mud can be recycled, however the mud formulation must often be adjusted due to compounds lost during the drilling process and imperfect separation of drill cutting particles and other drilling fluid additives. As examples of imperfect separations, drilling fluid can be absorbed or retained with drill cuttings during separation; conversely, drill cuttings having a small size can remain with the drilling mud after separations. Losses during the drilling process can occur due to the mud forming a filter cake, and thus depositing drill fluid additives on the wall of the wellbore.
Formation of a filter cake along the wall of the wellbore can occur throughout the drilling process, where drilling additives are used on a continuous basis. Filter cake formation can also be purposeful, such as in areas where drilling fluid circulation is lost. Lost circulation can occur in porous strata, requiring use of loss control additives to seal the openings in the formation, preventing loss of drilling fluids to the permeable formation and regaining drilling fluid circulation. Various agents and additives are known in the art to form formation seals and/or filter cakes on the wall of a well bore. These include sugar cane fibers or bagasse, flax, straw, ground hemp, cellophane strips, ground plastics, ground rubber, mica flakes, expanded perlite, silica slag, ground fir bark, ground redwood bark and fibers, grape extraction residue, cottonseed hulls, cotton balls, ginned cotton fibers, cotton linters, superabsorbent polymers, cellulose fibers, lignite, industrial carbon or graphite, and the like.
The formation of a filter cake along the wellbore may increase the stability of the wellbore. Additionally, use of certain additives, such as industrial carbon, in a loss control pill or throughout the drilling cycle can stabilize shale formations and other sections encountered while drilling. Improved wellbore stability can reduce the occurrence of stuck pipe, hole collapse, hole enlargement, and lost circulation and can improve well control.
While desiring improved wellbore stability, logistics and economics disfavor the use of industrial carbon throughout the entire drilling process. The disposal of the solids separated when cleaning the mud, including the industrial carbon, significantly increases the total amount of industrial carbon needed for the desired filter cake formation. The amount of industrial carbon thus required can increase the costs of drilling, and can require an excessive amount of storage space on a rig.
As an alternative to discarding all of the separated solids, a process of recovering and recycling polymer beads, which may be used as an additive in drilling fluids, has been contemplated. For example, U.S. Pat. No. 6,892,887 discloses a process for the separation and recovery of polymer beads from drilling mud, where a mixture of solid particulate materials, drilling fluids, polymer beads, and drilled solids are first passed through a shale shaker and/or a 10 mesh screen recovery apparatus; the large solid materials are discarded; and the remaining materials are passed through a hydrocyclone and a recovery shaker to separate the polymer beads and the fluids.
Polymer beads generally have a uniform size, i.e. spherical particles having a narrow particle size distribution, and have a significantly lower density, 0.8 to 1.4 g/cc, than the drilled solids and drill cuttings, approximately 2.6 g/cc. Additionally, polymer beads do not comminute or break down into smaller particles as readily as drill cuttings and other additives used in drilling fluids. These distinguishing properties facilitate the above recovery process.
It is desired in the industry to recover and recycle other drilling fluid additives, including industrial carbon. However, in contrast to polymer beads, the industrial carbon materials that are desired to be used throughout the drilling process are commonly supplied as particles, of varying particle sizes, uniformity, and shape. Additionally, the drill cuttings and formations encountered during drilling can return particles of similar shape and size to that of industrial carbon, and can comminute during circulation through the drill string, each of which can hinder recovery and recycle efforts.
Accordingly, there exists a need for a process useful in separating industrial carbon materials from drilling fluids and drill cuttings returned from the wellbore.